The present invention relates to fluids useful in subterranean operations, and more particularly, to improved viscoelastic surfactant gels suitable for use in certain subterranean applications that comprise non-aqueous tackifying agents, and their associated methods of use.
Treatment fluids may be used in a variety of subterranean treatments, including, but not limited to, stimulation treatments and sand control treatments. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The terms “treatment,” and “treating,” as used herein, do not imply any particular action by the fluid or any particular component thereof.
One common production stimulation operation that employs a treatment fluid is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more cracks, or “fractures,” in the subterranean formation. “Enhancing” one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation. The treatment fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the fractures. The proppant particulates, inter alia, may prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to the well bore. The proppant particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like, among other purposes, to enhance conductivity (e.g., fluid flow) through the fractures in which they reside. Once at least one fracture is created and the proppant particulates are substantially in place, the treatment fluid may be “broken” (i.e., the viscosity of the fluid is reduced), and the treatment fluid may be recovered from the formation.
Other common production stimulation operations that employ treatment fluids are acidizing operations. Where the subterranean formation comprises acid-soluble components, such as those present in carbonate and sandstone formations, stimulation is often achieved by contacting the formation with a treatment fluid that comprises an acid. For example, where hydrochloric acid contacts and reacts with calcium carbonate in a formation, the calcium carbonate is consumed to produce water, carbon dioxide, and calcium chloride. After acidization is completed, the water and salts dissolved therein may be recovered by producing them to the surface (e.g., “flowing back” the well), leaving a desirable amount of voids (e.g., wormholes) within the formation, which may enhance the formation's permeability and/or increase the rate at which hydrocarbons subsequently may be produced from the formation. One method of acidizing known as “fracture acidizing” comprises injecting a treatment fluid that comprises an acid into the formation at a pressure sufficient to create or enhance one or more fractures within the subterranean formation. Another method of acidizing known as “matrix acidizing” comprises injecting a treatment fluid that comprises an acid into the formation at a pressure below that which would create or enhance one or more fractures within the subterranean formation.
Treatment fluids are also utilized in sand control treatments, such as gravel packing. In “gravel-packing” treatments, a treatment fluid suspends particulates (commonly referred to as “gravel particulates”), and deposits at least a portion of those particulates in a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation zones, to form a “gravel pack,” which is a grouping of particulates that are packed sufficiently close together so as to prevent the passage of certain materials through the gravel pack. This “gravel pack” may, inter alia, enhance sand control in the subterranean formation and/or prevent the flow of particulates from an unconsolidated portion of the subterranean formation (e.g., a propped fracture) into a well bore. One common type of gravel-packing operation involves placing a sand control screen in the well bore and packing the annulus between the screen and the well bore with the gravel particulates of a specific size designed to prevent the passage of formation sand. The gravel particulates act, inter alia, to prevent the formation sand from occluding the screen or migrating with the produced hydrocarbons, and the screen acts, inter alia, to prevent the particulates from entering the well bore. The gravel particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like, among other purposes, to enhance conductivity (e.g., fluid flow) through the gravel pack in which they reside. Once the gravel pack is substantially in place, the viscosity of the treatment fluid may be reduced to allow it to be recovered. In some situations, fracturing and gravel-packing treatments are combined into a single treatment (commonly referred to as “FracPaC™” operations). In such “frac pack” operations, the treatments are generally completed with a gravel pack screen assembly in place with the hydraulic fracturing treatment being pumped through the annular space between the casing and screen. In this situation, the hydraulic fracturing treatment ends in a screen-out condition, creating an annular gravel pack between the screen and casing. In other cases, the fracturing treatment may be performed prior to installing the screen and placing a gravel pack.
Maintaining sufficient viscosity in the treatment fluids used in these operations is important for a number of reasons. Maintaining sufficient viscosity is important in fracturing and sand control treatments for particulate transport and/or to create or enhance fracture width. Also, maintaining sufficient viscosity may be important to control and/or reduce fluid loss into the formation. At the same time, while maintaining sufficient viscosity of the treatment fluid often is desirable, it may also be desirable to maintain the viscosity of the treatment fluid in such a way that the viscosity also may be reduced easily at a particular time, inter alia, for subsequent recovery of the fluid from the formation.
To provide the desired viscosity, polymeric gelling agents commonly are added to the treatment fluids. The term “gelling agent” is defined herein to include any substance that is capable of increasing the viscosity of a fluid, for example, by forming a gel. Examples of commonly used polymeric gelling agents include, but are not limited to, guar gums and derivatives thereof, cellulose derivatives, biopolymers, and the like. To further increase the viscosity of a treatment fluid, often the polymeric gelling agent is crosslinked with the use of a crosslinking agent. Conventional crosslinking agents may comprise a borate ion, a metal ion, or the like, and interact with at least two gelling agent molecules to form a crosslink between them, thereby forming a “crosslinked gelling agent.” Treatment fluids comprising crosslinked gelling agents also may exhibit elastic and/or viscoelastic properties, wherein the crosslinks between gelling agent molecules may be broken and reformed, allowing the viscosity of the fluid to vary with certain conditions such as temperature, pH, and the like.
The use of polymeric gelling agents, however, may be problematic. For instance, polymeric gelling agents may leave an undesirable gel residue in the subterranean formation after use, which can impact permeability. As a result, costly remedial operations may be required to clean up the fracture face and proppant pack. Foamed treatment fluids and emulsion-based treatment fluids have been employed to minimize residual damage, but increased expense and complexity often have resulted.
To combat perceived problems associated with polymeric gelling agents, some surfactants have been used as gelling agents. It is well understood that, when mixed with a fluid in a concentration above the critical micelle concentration, the molecules (or ions) of surfactants may associate to form micelles. The term “micelle” is defined to include any structure that minimizes the contact between the lyophobic (“solvent-repelling”) portion of a surfactant molecule and the solvent, for example, by aggregating the surfactant molecules into structures such as spheres, cylinders, or sheets, wherein the lyophobic portions are on the interior of the aggregate structure and the lyophilic (“solvent-attracting”) portions are on the exterior of the structure. These micelles may function, among other purposes, to stabilize emulsions, break emulsions, stabilize a foam, change the wettability of a surface, solubilize certain materials, and/or reduce surface tension.
When used as a gelling agent, the molecules (or ions) of the surfactants associate to form micelles of a certain micellar structure (e.g., rodlike, wormlike, vesicles, etc., which are referred to herein as “viscosifying micelles”) that, under certain conditions (e.g., concentration, ionic strength of the fluid, etc.) are capable of, inter alia, imparting increased viscosity to a particular fluid and/or forming a gel. Certain viscosifying micelles may impart increased viscosity to a fluid such that the fluid exhibits viscoelastic behavior (e.g., shear thinning properties) due, at least in part, to the association of the surfactant molecules contained therein. As used herein, the term “viscoelastic surfactant” refers to surfactants that impart or are capable of imparting viscoelastic behavior to a fluid due, at least in part, to the association of surfactant molecules to form viscosifying micelles. Moreover, because the viscosifying micelles may be sensitive to hydrocarbons, the viscosity of these surfactant fluids may be reduced after introduction into the subterranean formation without the need for certain types of gel breakers (e.g., oxidizers). The term “breaker” is defined herein to include any substance that is capable of decreasing the viscosity of a fluid. This may allow a substantial portion of the surfactant fluids to be produced back from the formation without the need for expensive remedial treatments.
However, the use of treatment fluids viscosified with conventional polymeric and viscoelastic surfactant gelling agents may be problematic in certain subterranean formations exhibiting high temperatures (e.g., above about 200° F.). Many conventional gelling agents become unstable at these temperatures, which reduces the viscosity of the treatment fluid. Moreover, the stability of viscosifying micelles in viscoelastic surfactant gels may be extremely sensitive to various conditions (e.g., temperature, pH, presence of other additives in the fluid, composition of the subterranean formation, etc.), and thus the inclusion of other additives in the treatment fluid that are needed for a given treatment using that fluid may detrimentally affect the rheological properties (e.g., viscosity) of the fluid. Generally, the introduction of additional components (e.g., resin-coated proppants) into viscoelastic surfactant gels is thought to reduce the viscosity of those gels. The inability to maintain a desired level of viscosity, among other problems, may increase fluid loss and decrease the ability of the fluid to suspend and/or transport particulate materials.